A wellbore used in recovering oil/gas typically includes a production string placed within a casing string. In some wellbore designs, the entire length of the wellbore is lined with the casing string, which is cemented within the wellbore. Alternatively, in open-hole designs, the casing string is limited to an upper portion of the wellbore and lower portions of the wellbore are open. In both open-hole and cased-hole designs, the production string is typically placed into the lower portions of the wellbore and mechanical or hydraulic packers are used to radially secure the production string in a predetermined location. The outside diameter of the production tubing is less than the diameter of the internal wellbore or production casing, thereby defining a tubular annulus.
To gain access to oil/gas deposits in the general area of the wellbore, selected portions of the production casing are perforated or, alternatively, sliding sleeves or other devices are used to provide a conduit to the oil and gas deposits. To enhance the flow of oil/gas into the tubular annulus, and to thus increase flow into the production tubing, hydraulic fracturing (i.e., “fracing”) of subterranean formations may be required, especially in low permeability formations. That is, in some instances subterranean formation that the wellbore penetrates does not possess sufficient permeability for the economic production of oil/gas so hydraulic fracturing and/or chemical stimulation of the subterranean formation is needed to increase flow performance.
Hydraulic fracturing consists of selectively injecting fracturing fluids into a subterranean formation in openhole or via perforations or other openings in the production casing of the wellbore at high pressures and rates to form a fracture. In addition, granular proppant materials, such as sand, ceramic beads, or other materials are injected into the formation with the fracturing fluids to hold the fracture open after the hydraulic pressure has been released. The proppant material prevents the fracture from closing and thus provides a more permeable flow path within the subterranean formation, resulting in increased flow capacity. In chemical stimulation treatments, permeability and thus flow capacity is improved by dissolving materials in the formation or otherwise chemically changing formation properties.
To gain access to multiple or layered reservoirs, or a very thick hydrocarbon-bearing formation by hydraulic fracturing, multiple fracturing zones are established and stimulated in stages. One technique currently being used with significant results utilizes the use of a directionally drilled well into a single reservoir. By drilling the well in a substantially horizontal orientation through the reservoir, the reservoir can be fractured in multiple locations to substantially improve the flow rate. To stimulate multiple fracturing zones, a target stimulation zone must be temporarily isolated from the already-stimulated zones to prevent injecting fluids into the already-stimulated zones. Various methods have been utilized to achieve zonal isolation, although numerous drawbacks to the current methods exist.
A common method currently used to isolate a fracturing zone in multistage fracturing utilizes composite bridge plugs. According to this method, the deepest zone in the wellbore (or most distal in horizontal wellbores) is stimulated. Then, the stimulated zone is isolated by a bridge plug that is positioned above the perforations associated with the stimulated zone. The process is repeated in the next zone up the wellbore. At the end of the stimulation process, a wellbore clean-out operation removes the bridge plug. The major disadvantages of using one or more bridge plugs to isolate a fracture stimulated zone are the high cost and risk of complications associated with multiple trips into and out of the wellbore to position the plugs. For example, bridge plugs can become stuck in the wellbore and need to be drilled out at great expense. A further disadvantage is that the required wellbore cleanout operation may block or otherwise damage some of the successfully fractured zones.
Another method used to isolate a fracturing zone utilizes frac baffles and balls. The first baffle, which contains the smallest inside diameter, is placed in the most distal portion of the wellbore. The succeeding baffles increase in diameter and are installed above the previous baffle. To achieve zonal isolation, a frac ball of a predetermined size is dropped that seats on the corresponding frac baffle at a specified depth or position to block a portion of the wellbore. The isolated zone is accessed by perforations or a sleeve is shifted then stimulated. After each stage, the process is repeated until all selected frac zones in the well are fracture stimulated. On the last day of operation, the frac balls typically are flowed back to the surface during the flow back of the fracturing fluids. The primary advantage of this method is that the frac baffles are installed within the casing and can be activated by dropping a ball from the surface, with little downtime between fracture stimulation stages. The disadvantages include the need to use progressively larger sized balls for subsequent fracturing stages, thus limiting the number of zones that can be treated for a given casing diameter. Additionally, the frac baffles and balls may need to be milled out of the casing string, which increases the number of wellbore operations and inherent risks and costs associated therewith.
One method for successfully isolating one or more production zones utilizes a sliding sleeve that is associated with a tubular string, which may include casing, liners, tubing, etc. Opening the sleeve permits zonal isolation and stimulation of the formation via the tubular string through the selected sleeve. The sleeve can be operated by using a mechanical/hydraulic shifting tool attached to coiled or jointed tubular or by using a ball-drop system. In a ball-drop system, a ball pumped down the tubular string engages a sliding sleeve and shifts the sleeve from a closed position to an open position, thereby opening a passageway to the tubular annulus. The ball also isolates the already-stimulated zones located beneath the open sleeve. The advantages of this method are that the tubular annulus can be accessed without requiring various tools or costly trips into the wellbore to isolate the various formations. However, the method is limited by the need to use progressively larger sized balls for subsequent fracturing stages, thus limiting the number of zones that can be deployed for a given tubing string diameter. This system inherently restricts the production flow rate due to the necessity of using progressively smaller balls to open and close the sleeves.
Accordingly, a need exists for an improved downhole tools and methods that efficiently isolates individual zones of a subterranean formation while (1) ensuring that stimulation fluids are directed to the desired location, (2) maintaining a desired inner diameter of the tubing string, (3) reducing the time between stimulations, and (4) is mechanically simplistic to operate and cost effective.
The following disclosure describes improved downhole tools and methods for selectively isolating downstream portions of a tubular string while simultaneously allowing access to the tubular annulus of a wellbore such that a selected zone may be stimulated. The improved downhole tools and methods do not limit the number of fracture stimulation stages created in a vertical or directional wellbore. As used herein, ‘downstream’ and ‘lower’ refers to the distal portions of a tubular string disposed toward the toe of the wellbore. Further, as used herein, ‘treatment fluid’ may comprise acid, proppant material, gels, or other stimulation fluids generally used in the art.